Golar LNG Ltd

NASDAQ:GLNG

Earnings Call Transcript 2021-Q3

[Operator]

Good afternoon, ladies and gentlemen, and welcome to the Golar LNG Limited Third Quarter 2021 Conference Call. At this time, all participants are in listen-only mode, until we conduct the question-and-answer session on the phone and on the web. Just to remind you all, this call is being recorded.

I would like to hand over to your Mr. Karl Staubo. Please begin your meeting.

[Karl Staubo, Chief Executive Officer]

Hi, all, and welcome to Golar LNG's Q3 earnings results presentation. We would like to thank you for taking time to dial in. My name is Karl Fredrik Staubo, the CEO of Golar LNG.

Before we get into the quarterly results, please note the forward-looking statements on slide two. I'm accompanied today by our CFO, Mr. Eduardo Maranhao, to present this quarter's results. Turning to slide three and Q3 highlights.

We report revenue for the quarter of $107 million, a year-over-year increase of 12%, and an adjusted EBITDA of $74 million, up 30% year-over-year. We expect to continue to see a strong growth in our earnings across both our FLNG segment and Shipping, and we'll get into the details of which throughout this presentation. Starting off on FLNG, we continue to deliver 100% uptime on Hilli, which now has delivered its 63rd LNG cargo, more than any other FLNG globally. Furthermore, we hedged 50% of our TTF linked commodity exposure for Q1 '22, at $28 per MMBtu, implying a Q1 earnings from our train 3 production of $21.2 million for the quarter.

We also see increasing contribution from our Brent-linked earnings, and together, the commodity linked production from Hilli is expected to more than double Golar's [indiscernible] earnings from Hilli, in 2022, versus the last 12 months earnings. FLNG Gimi is now 75% technically complete, and scheduled to start its 20-year contract for BP in just about two years. This will unlock an EBITDA backlog to Golar of $3 billion. We also experienced increased momentum for potential new FLNG projects.

We continue constructive discussions with an existing customer for use of a five million ton Mark III new build. And we're also making rapid progress on potential integrated projects. We have also seen an increase in the amount of prospective FLNG customers in the quarter across different geographies.

Turning to Shipping, our Shipping portfolio achieved a TCE of $49,500 a day for the quarter, up 26% year-over-year. We expect to see increased earnings also from this segment going forward due to increased spot exposure of our fleet opening up through 2022. We have recently contracted one of our ships for a one-year time charter at about $100,000 a day, increasing our revenue backlog for the Shipping segment to $267 million. We see continued strengthening for LNG shipping with increasing interest for three to five-year charters, increasing asset values driven by new building prices, and increasing day rates.

On corporate and investment, we secured $682 million in new financings during the quarter. The proceeds from these financings will be used to refinance our upcoming convertible bond maturity, as well as extend maturity of other vessel financings. We now have no material debt maturities until after the FLNG Gimi delivers an increased financial flexibility to fund attractive FLNG growth project.

I will now turn the call over to Eduardo to take us through the third quarter results.

[Eduardo Maranhao, Chief Financial Officer]

Thanks, Karl, and good morning, everybody. I'm very pleased to provide an update on our financial results for the third quarter of 2021. So, turning to slide number five, we can see that the group had a very solid performance in the third quarter. Total operating revenues increased to $107 million in Q3, this was an increase of 13% from the same quarter of last year. Operational performance was really strong, and adjusted EBITDA came in at $74 million this quarter, up 30% year-on-year.

This quarter, we recorded a net loss of $91 million; this was mainly driven by a non-cash mark-to-market adjustment of $157 million to the value of our New Fortress Energy shareholding at the end of September. This was partially offset by realized and unrealized gains on our oil and gad derivatives of $73 million. I will talk more about this in this presentation. The increase in total operating revenues can be attributed to a strong and improving shipping performance. TCE earnings across our shipping fleet increased to $49,500 per day in Q3, up 13% on Q2, and 27% more than last year's Q3 numbers. We expect it will continue to increase as the shipping fleet will be re-contracted at higher expected rates.

Total operating revenues from our FLNG Hilli, including [indiscernible] were $55 million in Q3, in line with $55 million in Q3 last year. This number was further enhanced when including the Brent-linked revenues. This oil-linked component of Hilli generates additional operational cash flows of approximately $3.1 million for every dollar increase in Brent crude prices above $60 per barrel. As a result of rising prices, an $8.9 million realized gain on the oil derivative instrument was recorded in Q3, up from $3 million we realized in Q2. Adjusted EBITDA from Shipping was $30 million this quarter, an increase of 58% when compared to Q3, 2020.

FLNG contributed with $49 million this quarter, also reflecting an important increase of 20% when compared to the same period of last year. We expect adjusted EBITDA generation from our FLNG segment to grow four times from current levels over the next two to three years, on the back of contracted earnings from Gimi and increased earnings from our commodity exposure on Hilli. Our balance sheet continues to strengthen. At the end of Q3, our total contractual debt was $2.1 billion, down 11% from the same period of last year. At the same time, our total cash position has increased by 15% year-on-year, to $203 million.

So, moving on to slide number six, as Karl mentioned before, we have secured up to $682 million in new financing facilities, which include a new four-year $300 million unsecured bond, which we priced in October, the refinancing of our FSRU Golar Tundra for up to $182 million, a new three-year corporate RCF of $200 million. And we have also obtained approval to extend the maturity of one of our vessels, in this case, the Golar Seal, for another three years, from January, 2022, to January 2025. So, the combination of those facilities has allowed us to extend our key debt maturities, at the same time as reducing the interest costs on existing facilities.

More importantly, these initiatives have enabled us to address the refinancing of our convertible bond on favorable terms and substantially improve our balance sheet flexibility. Between now and the expected delivery of our FLNG Gimi in 2023, there are no material debt maturities. While there are some shipping related maturities in the next few years, we remain extremely confident on our ability to address these re-financings based on the low into value levels of such passage.

So, moving on now to slide number eight, I would like to talk a little bit more about the incredible performance of our FLNG Hilli. In Q3, she achieved another quarter of 100% commercial uptime, and generated more than $50 million in adjusted EBITDA to Golar. This quarter, we had the 63rd cargo recently offloaded, producing more LNG than any other floating liquefaction unit in the world. Tailings from increased oil and gas prices will provide meaningful earnings upside with no additional CapEx. We expect to generate approximately $13 million from our Brent-linked fees in Q4. And based on forward market prices, we are increasingly optimistic for the future contributions in 2022.

We have also agreed to increase 2020 production by 200,000 tons, an important feature of this agreement is that it allows us to benefit from exposure to TTF gas prices for that incremental production. And speaking of gas prices, we have recently hedged part of our Q1 '22 exporter at a price of $28 per million Btu, that implies a net income to Golar for the first quarter of next year of approximately $21 million, just from that incremental production alone.

Lastly, this incremental production can be even further extended, based on a potential three-year option, which we have agreed with the customer, which could potentially increase production by up to 400,000 tons to 1.6 million tons per year from 2023 to 2026.

I'll now turn the call back over to Karl.

[Karl Staubo, Chief Executive Officer]

Thank you, Eduardo. Turning to slide nine and diving into some more of the detail of what this incremental increase in production could equate to in dollars. So, Hilli was originally contracted for half of its installed capacity, or 1.2 million tons of the 2.4 million tons of installed capacity.

Golar share of the EBITDA generation of this initial 50% of utilization is $74 million of fixed annual tolling fee plus an oil derivative where Golar makes $2.7 million of EBITDA for every dollar Brent is above 60.

In July, we announced an increased capacity utilization to increase production from 1st of January 2022 by 0.2 million tons or from 50% to 58% in capacity utilization. The tolling fee for this 8% increment production is linked to the TTF gas price. On current TTF prices, the incremental 2022 revenue generation from the increased production is $85 million to Golar. A $1 change in the TTF price corresponds to $2.8 million change in EBITDA, if you have a different view about the TTF price, you can run your own sensitivity. Sure, the more we grounded Perenco, the charter of Hilli, a one-time three-year option to increase production from Hilli from 2023 until end of its current contract in July 2026.

The increase for those three years would be from 4.4 million tons or from 50% to 66% capacity utilization. The 16% optional volume has a tariff equivalent to the increased capacity utilization for '22 linked to the TTF price. Again at current TTF prices that would equate to $164 million in annual EBITDA to Golar, again, sensitivity here would say that the dollar change in the TTF price would correspond to a $6.5 million change in EBITDA. Perenco needs the clear option for the 23 to 26 production during the first-half of 2022. They are currently having a drilling program to tie in more reserves to the unit, and we expect the option to be declared should the results of the ongoing drilling campaign be successful. Important to highlight is that Golar will incur no capital expenditures to facilitate the capacity increases and all EBITDA generated will flow straight to net income.

Turning to slide 10, and then update on the Gimi Construction, Gimi is now 75% technically complete with more than 13 million man hours work to date. Engineering work and procurement of all critical components are now more than 99% complete and remaining work is mainly construction and commissioning. We're about two years from full contract startup, which will start cash flow generation from Golar's currently invested capital of $540 million unlocking annual EBITDA generation to Golar of $151 million every year for 20 years.

Turning to slide 11, we believe Golar is uniquely positioned for attractive FLNG growth. And we will now increase our focus on integrated projects. We're increasingly encouraged by the FLNG market opportunity and we'll explain why. Starting on the top left, this is an illustrative value chain for FLNG projects. Lifting the gas from the reservoir to surface cost around $1 per MMBtu. FLNG tolling arrangements typically range from $2 to $3 dependent on duration and credit quality of the counterpart.

You don't need to ship the LNG to it end user and current shipping rates that's around another $1.50 per MMBtu. That means that you can deliver gas in Asia with a breakeven of around $5 per MMBtu. Comparing that to current gas prices at $32 per MMBtu leaves the margin of around $28 per MMBtu. This equates to an EBITDA generation of $3.3 billion for a $2.5 million on FLNG or an almost $7 billion margin for a $5 million on FLNG. These margins are what's driving the increased interest from prospective charters for new FLNG projects and also explains our desire to seek increased commodity linked FLNG contracts. Obviously, the current gas price environment is very high. So, taking a look at this in a historical context on the top right, you can see the green line would be the cash breakeven of a $5 landed gas in Asia. And you can see that compared to historical gas prices, is an extremely attractive risk reward, it's extremely few scenarios where you do not make money. And for the most part, you make extremely healthy margins.

Lastly, we believe the strong demand pool on LNG suggests that LNG prices should be stronger for the next 10 years versus the previous 10 years, which furthermore supports this strategy. On the bottom half of the page, we have compared the carbon footprint of our FLNG technology to other land based and offshore gas liquefaction plants. Our technology ranked best-in-class and we experience that this is an increasingly important attribute for our FLNG technology when new charters consider to take investment decisions for new gas developments. Hence, we continue to view the underlying macro as highly supportive of our initiatives to build out on integrated FLNG projects.

Turning to slide 12, we try to shed some more lights on where we see the most interesting FLNG opportunities arising. As mentioned, we have seen an increasing amount of new project in new geographies considering FLNGs for proven gas reserves. The most active development remain invest Africa and the Middle East, where there are abundant gas resources of high quality, low cost, natural gas reserves. We are currently in discussions for both tolling base and integrated projects in these regions.

Turning our attention to shipping on slide 14, we also expect to see continued strengthening earnings from our shipping segments. As Eduardo mentioned, our shipping TCE for the quarter came in at $49,500 a day and we expect Q4 2021 TCE at around $53,500 a day. We are confident that we will see an increased earnings from this segment. We've tried to illustrate that by the dark blue bars on the left hand side, which represent the number of vessel days on charter. The night blue coloring represents spot exposed vessel days. Hence you can see that the fleet will develop from the current 100% fixed days to about 50% spot exposure in Q4 of 2022. The stapled red line represents our last 12 months EBITDA of $50,900 a day. That is significantly lower than where we concluded a five-year charter this summer and looked lower than where we recently fixed one of our ships on a one-year charter of around $100,000 a day. Last 12 months EBITDA was $130 million, a $10,000 change across our shipping fleet corresponds to $32 million change to EBITDA.

We're encouraged by the longer term outlook for LNG shipping on the back of increasing charter interest for three to five-year charter coverage, increasing asset values as a result of higher new building prices and increased earnings. These factors together with deleveraging of Golar shipping fleet has created a healthy equity value in our shipping segments, and we will remain opportunistic in evaluating alternatives for further group simplification by potentially separating this part of our business into a separate vehicle.

Turning to slide 15, the shipping market has strengthened as expected with the main driver being a widening of the arbitrage between Europe and Asia adding long-haul trade to an already pipe market. Broker quotes are in excess of $200,000 a day and rates are generally up year-over-year across the entire every single month. On the right-hand side, the current geographical arbitrages in LNG prices support continued strong rates through 2022. From 2023, we will also see the full impact of new environmental regulations impacting the effective available supply, creating longer term support for rates, which in turn explains why charters are out to fix longer-term coverage in the current markets.

On slide 16, we have highlighted some other key supply and demand events that are affecting LNG carrier markets and the LNG commodity prices across the board. On the demand side, we see the higher frequency of extreme weather condition causing higher peaks in heating and cooling demand. We see a broad rebound in Asian LNG demand, which is 10% up year-to-date with Chinese LNG demand up above 20%. We see stable demand in Europe on low renewable output. We see high demand for LNG in South America, especially due to dropped and limited supply from hydropower in Brazil, which LNG imports are up 600% year-to-date.

On the supply side, we see reduced volumes from Russia to Central Europe limiting flows to Northwest Europe. We see reduced supply from a number of producers, including Trinidad, Nigeria and Peru. European storage levels are below the five-year average and the hurricane season impacting this ability of U.S. supplies. So, all in all these extremes impact the market higher volatility, which at the end of the day we think benefits our business model and shipping in particular.

Turning to slide 17, we continue our efforts to reduce our carbon emissions and have express targets to reduce our fleet wide carbon intensity by 25% within 2030 versus 2019 levels. We have also evaluated our entire fleet according to the new EEXI and CII environmental regulations we are - where we are well within all emissions standards for our entire fleet with the exception of the Golar Arctic. Arctic is the only remaining steam carrier in our fleet and we are exploring commercial alternatives for her ahead of new regulations becoming effective 1st of January 2023. We're committed to continue the work to cut emissions on our shipping as we see increasing focus from the industry to push the boundary and enable LNG to be part of the path towards net zero.

Turning to the last section, corporate and strategic focus on slide 19, we believe LNG will continue to play a vital role in the transition towards cleaner sources of energy. We have included here a slide by BP presented in the world energy outlook for 2020. The world today consumes around 260 million barrels of oil equivalent of energy demand per day. Today, this is serviced 60% by oil and coal and only 40% by other sources of energy.

BP expects that by 2030 world energy demand will increase by 8% to 280 million barrels of oil equivalent per day. In the same time period, oil and coal is assumed to reduce its market share from to 60% to 49% of the global energy mix. And in order to meet this increased energy demand offsets the reduced energy supply from oil and coal, BP expects LNG and natural gas to be the second fastest growing source of energy after renewable. LNG attributes as the cleanest alternative of hydrocarbon fuels and its flexible nature in creating backup base load energy supply enables rollouts of renewables. At LNG power plants work has a buffer at times where there is not sufficient sun, wind or rain to produce from renewable energy sources. This gives us comfort that we operate in a global growth market and supports our view that gas demand and gas prices will likely be higher in the next 10 years versus the previous 10 years supporting FLNG growth project.

Slide 20 summarizes Golar's embedded earnings power in one slide. If we then go segment by segment, on shipping we made an EBITDA of $130 million last 12 months. As explained, we expect to see a significant increase in EBITDA generation as current market rates for LNG carriers is significantly higher than for the charters that are rolling off. Again $10,000 change across our shipping fleet equates to $32 million change to EBITDA. If you were to mark to market the entire shipping fleet, you could see rates more than double and go all the way up to $287 million in the course of the next one to two years.

Turning to Hilli, we made $92 million last 12 months, which comprised of $74 million of fixed tolling fee and $18 million of oiling revenues. We expect to see strong growth in EBITDA development from 1st of January next year on the back of increasing Brent linked revenues, as well as startup of the TTF link volumes, all generated with no incremental CapEx to Golar. Turning to Gimi, Gimi is the unit currently under construction, which will start its 20 year contract with BP from Q4 2023. This unit will generate $151 million to Golar every year for 20 years. Gimi is the only unit in our portfolio where there's any remaining CapEx with $426 million of total CapEx where $203 will be covered by debt and $223 million by equity.

If we net off G&A, we derived at the last 12 months EBITDA of $206 million. Adding the fixed EBITDA contribution from Gimi, this will increase EBITDA generation to about $360 million. Further adding commodity linked FLNG revenues and increased shipping rates could see EBITDA developing closer to $500 million to $600 million within the next two to three years and this is before adding any growth projects. Our contractual debt stands at $2.1 billion remaining CapEx of $0.4 billion and cash and marketable securities at $0.7 billion. This suggests a net debt, including remaining CapEx, for $1.8 billion.

Turning to the last slide, summary and outlook, on FLNG, we expect EBITDA generation from our FLNG segment to quadruple during the next two to three years, driven by commodity-linked revenues for Hilli, and Gimi coming on stream. Our market-leading operational track record, our proven low-cost design, and industry-leading carbon footprint positions Golar to capitalize on increased demand for LNG projects supported by stronger LNG prices. As alluded to, we see increased momentum from new tolling fee and integrated projects.

We also expect to see increased earnings from our Shipping segment as we increase market exposure to stronger rates than those rolling off. Lastly, on Corporate, with new $682 million of new and refinancing facilities secured, we have no material debt maturities until Gimi delivers. We see increased financial flexibility and strengthening market fundamentals, enabling funding of FLNG growth projects, and potential further group simplification. We're optimistic about the direction of our business, and believe Golar is well-positioned to capitalize on the current macro tailwinds benefiting our operational and financial leverage going into 2022.

That concludes Golar's Q3 2021 earnings presentation. Thank you all again for dialing in to the call, and we'll now turn the call over to the operator for any questions.

[Operator]

Thank you. [Operator Instructions] Our first question comes from the line of Randy Giveans from Jefferies. Please go ahead with your question.

[Randy Giveans, Jefferies]

Howdy, Karl and Eduardo. How's it going?

[Karl Staubo, Chief Executive Officer]

Hey, Randy.

[Eduardo Maranhao, Chief Financial Officer]

Hey, Randy.

[Randy Giveans, Jefferies]

Hey. So, yes, first, obviously congrats on the increased throughput for Hilli train 3, I know it's been a long time coming, so a few questions around this, can more of that 200,000 tons, in 2022, be pulled into the first quarter to kind of take advantage of the elevated LNG prices or is it capped, basically, at 50,000 tons per quarter throughout next year? And then secondly on that, any reason this can't start before January 1, or is there some specific deadline or a start date there? And then lastly, any hurdles or timeline around the further expansion of this, obviously it's [indiscernible] option here in the first-half of next year?

[Karl Staubo, Chief Executive Officer]

Yes, sure. So, for now the 200,000 tons is equally distributed throughout next year, so think of it as 50,000 a quarter.

[Randy Giveans, Jefferies]

Yes.

[Karl Staubo, Chief Executive Officer]

As we have with the current production, there is room for some overproduction that can be fine-tuned into each quarter. But that's equally dependent on gas flows and gas prices. So, it's not very easy to move all of that into the high gas prices of Q1. When it comes to further expansion, they are currently undergoing a drilling program. They need to declare the option during the first-half of next year. They originally committed to drilling one well. We have been made aware that they're now drilling four wells to secure the incremental production. So, if it was likely that they declared the option with one well, we think it's four times as likely that they will do it with four wells.

And with this gas price and the stable operation of Hilli, we think it's in everybody's interest to declare the incremental volume from '23 to '26. And we remain very optimistic that they will.

[Randy Giveans, Jefferies]

Got it. And then the other quick part of that question, any way to turn that on a little earlier than January 1, to get some 4Q upside?

[Karl Staubo, Chief Executive Officer]

We believe this will happen from January 1, that's the contractual obligation.

[Randy Giveans, Jefferies]

Got it. All right, and then kind of turning to your balance sheet, clearly in great shape there, no debt maturities till 2024, minimal CapEx really, even including Gimi. So, I guess two questions around that. First, on the converts and just the timing of redemption, do you expect that here in the fourth quarter or waiting until February? And then secondly, what's the next use of this additional liquidity? Is there any maybe share repurchase authorization, your share are kind of stubbornly trading at $13-$14, over the focus beyond further reducing the debt from the LNG carriers?

[Karl Staubo, Chief Executive Officer]

Do you want to take one, Eduardo?

[Eduardo Maranhao, Chief Financial Officer]

Yes, sure. So, hi, Randy. So, when it comes to the redemption of the convertible bonds, in connection with the [insurance] [Ph] of the unsecureds, we have repaid $85 million out of the $402 million of converts. So, we remain with 317, which will mature in February. And we plan to redeem those bonds upon maturity, so we have no plans to further repay any other bonds before that date.

[Randy Giveans, Jefferies]

Okay.

[Eduardo Maranhao, Chief Financial Officer]

And -- but $85 million has already been prepaid right in connection with the bond issuance. And when it comes to the share repurchase, we still have, as approved by the Board, up to $25 million of an allowance to complete our share buyback program. But we have no further plans or no intentions to do it in the near-term.

[Randy Giveans, Jefferies]

All right, well, I guess, that's it for me. I'll let someone else ask about the LNG spin potential. Thanks so much.

[Eduardo Maranhao, Chief Financial Officer]

Thank you.

[Karl Staubo, Chief Executive Officer]

Thank you, Randy.

[Operator]

[Operator Instructions] Our next question comes from the line of Ken Hoexter from Bank of America. Please go ahead with your question.

[Ken Hoexter, Bank of America]

Great. Hey, Karl and Eduardo. Can you talk about the progress of the FLNG discussions? Are they more Mark III? Is anything popping up on the Gandria? Maybe just provide us, it sounds like you're accelerating some of those discussions, we've heard that a lot from Golar over the past. So, I just want to see what stage do you think they're at, and how far they're progressing?

[Karl Staubo, Chief Executive Officer]

Yes, hi, Ken. So, I think we got the same question in the July, on the Q2 call. And at that time, we said we think that there will be material FLNG news within six to 12 months. At that time we said more likely six than 12. And I think we would stand by that guiding, and that was in August. So, that gives you some perspective on where we see timing. And when it comes to [what type of] [Ph] project, we are making progress on both tolling base and integrated contacts. So, I think there's -- if you listen to Cosmos' quarterly call yesterday, they discussed Phase 2 FID decision for the Tortue field during 2022. And on that field, all of the infrastructure, apart from the FLNG, is built to accommodate LNG production of five million tons, and we have three-and-a-half today.

On integrated projects, that should be done by Gandria, but also some of the other FLNG solutions. So, I would say that on the tolling fee, I think it's more likely that will go the Mark III [indiscernible]. And on the integrated project, we'll probably utilize smaller volumes, and then a Mark I or a Mark II device.

[Ken Hoexter, Bank of America]

Great. Sounds like something's coming verily in the next couple months, so look forward to that. Thank you. And then the increase in production maybe just a little bit more following Randy's questions. But is that on the -- that the first two trains, is this all on the third train? Are you -- do you still have any access to grow that potential of the fourth train? And maybe time frame when they have to give you that answer in '22, is it -- you mentioned, is it over the next couple of months that we're looking for an answer, and scale and size? Thanks.

[Karl Staubo, Chief Executive Officer]

Yes, sure. So, just to be clear, Hilli has got four trains, and we produce from all four trains today, we interchange which trains we produce from. Just think of it as buying a new car. Even if it's a new car, you don't let it sit still in your garage for four years, and then go and try to start it. So, you want to make sure that it's kept up to speed and sort of works as it's supposed to do. So, we keep on interchanging which trains we produce from. But you're right, that we only produce 50% of our utilization. And if you want to equate that into trains, that's train 1 and 2. The incremental production is, for '22, an increase of 8%, and potentially from '23 to '26 of 16%. All of that can be satisfied from train 3, even if we interchange between all the four trains and they need to declared up during the first six months of 2022 or before the end of the summer, we should know at the latest.

[Ken Hoexter, Bank of America]

All right, and then the incremental, you mentioned just comes from that any incremental comes within those three trains. You're still not looking at upscaling it to the fourth yet, even with the interchange.

[Karl Staubo, Chief Executive Officer]

That has to do with the gas resource that we're producing from and the amount of gas flow that Perenco can allow themselves to extract while still have this firing the off-take agreements that they have entered into until July 2026.

[Ken Hoexter, Bank of America]

Perfect. Those are my two, appreciate the time. Thanks, Karl. Thanks, Eduardo.

[Karl Staubo, Chief Executive Officer]

Thanks.

[Eduardo Maranhao, Chief Financial Officer]

Thank you.

[Operator]

Our next question comes to line of Ben Nolan from Stifel. Please go ahead with your question.

[Frank Galanti, Stifel Nicolaus]

Yes, great. This is Frank Galanti on for Ben. Thanks for taking our question. I wanted to follow-up on the Hilli kind of thinking longer-term. Can you walk through the potential options for the Hilli and Perenco kind of looking out past 2026? Is it -- in other words, is it -- at the end of the contract, is it just to sign a new longer term contract with more volume or nothing? Are there other options that that could provide that additional gas needed?

[Karl Staubo, Chief Executive Officer]

Yes, sure. And so I think we have all along said that we are not going to talk about extension before we get paid for the full capacity utilization of the unit. And we think the increased production from January 1 is one step in that direction. The further increase or potential increase from 23 to 26 is another step in that direction. Should that be declared, then we could be open to discuss that with Perenco until it is declared or not, but with the proven track record of Hilli and the current gas price, Hilli is an increasingly attractive unit to several potential charters. And our target is to deploy her on an integrated contract where we get more of the upside.

[Frank Galanti, Stifel Nicolaus]

Okay. Yes, that's helpful. And then I guess for my second question, thinking about stranded gas or more specifically gas is currently flared providing an opportunity to monetize that is clearly an obvious solution. But those deals and has sort of been hard to materialize. Could you talk through some of the challenges on, on that type of gas sourcing and then in kind of what the expectations are from your perspectives on being able to solve those problems?

[Karl Staubo, Chief Executive Officer]

I think the key factor as to why the FLNG, FIDs have been slower than at least Golar originally anticipated that's purely been the gas price. So, if you look at where the gas price was over the course of the last four or five years, it's mainly been driving downstream, which is why we kind of shifted focus for a bit and built Golar power, which later change the name to Hygo and then sold to GMLP. Now that the gas price is currently on spot, but also on forward curves back in the territory that supports upstream investment. We think that's the key driver of unlocking new FLNG project. So, first and foremost, it's driven by both current, but equally important forward picture of LNG prices. That's the key driver. Other call it stumbling blocks that you need to close is to have all of the regulatory permits in the specific field to be allowed to use LNG exports, which includes some time, time consuming government approval.

[Frank Galanti, Stifel Nicolaus]

Okay, very helpful. Thanks very much.

[Operator]

Our next question comes from the line of Mike Webber from Webber Research. Please go ahead with your question.

[Mike Webber, Webber Research]

Hey, good morning guys. How are you?

[Karl Staubo, Chief Executive Officer]

Hey, Mike.

[Eduardo Maranhao, Chief Financial Officer]

Well, thanks.

[Mike Webber, Webber Research]

Good. Some of this has already been parsed over, but in looking at the deck looks like you guys put some energy into kind of re-carving it a little bit and then showing it a bit differently, which is appreciated looks good. But the one thing that's a little bit absent here is I think Randy even references at the end of his time that there's not a lot of color on the strategic review and what you plan to do with the LNG carriers. I know that's -- Ell, there's only so much you're going to be able to get into there, but particularly as it pertains to your ability to go out and chase additional FLNG business, and your ability to finance that at attractively, having the volatility especially the LNG carriers on the balance sheet has been an issue for Golar historically. So, I'm curious, do you think you'll -- do you think it's likely that you end up executing or -- on a spin or finding the right strategic solutions for the LNG carrier fleet before you would consider pursuing formally or FID-ing an FLNG project that would likely run you $1 billion to $2 billion and put you back into the financing market.

[Karl Staubo, Chief Executive Officer]

We do not see the shipping spin as a requirement to do new FLNG projects at all that that's absolutely not an issue the way we did. As we have highlighted in the past, right now we very much like the outlook both for FLNG and shipping, but we have to admit that we think our uniqueness mainly sits in the FLNG segment because that's where we have a unique competitive edge. So, as much as we like both segments, we think that it could be that we could better extract the value from the two segments if they were separately listed vehicles and will continue to be opportunistic in pursuing such venues. And once we have something to update the market with, I'm pretty convinced we will.

[Mike Webber, Webber Research]

Got you. And just to dig into that a little bit, if you're looking at a Mark III and 5 MPTA, you're likely going to be building that's somewhere where you can get export financing, that's just going to be a larger endeavor. If you're looking at placing a second FLNG asset in Tortue, right, to your point earlier, it's likely a Mark I or Mark II. I would assume then the presumption is you would be doing that in China, Korea, not in Singapore from a financing availability perspective. But if I think about the -- if I prioritize the projects that you're looking at, I know you've made a big shift to look at the Mark III and the 5 ton market. Do you think it's more likely you look at something that large as your next project? Or are you going to be back into that 2.5 million ton market for Tortue? It sounds like Tortue it seems like it's been the front runner for quite a long time, but I just want to make sure we're clear on that because obviously that has implications on the importance of spending the carriers of the way you kind of address your balance sheet.

[Karl Staubo, Chief Executive Officer]

We have cash and marketable securities north of $700 million today. I think one of the key things that's changed for FLNG's since the initial Hilli is -- at that time this was not the proven concept and no one knew if this would actually work in practice. The unit is now operated with 100% utilization since 2018. It is a proven concept and BP has ordered a similar unit. So, it's starting to become more of a generic asset. It's not like an FPSO that's custom made to the field. It's a generic asset. So, we do see financing availability for these units, very different from when we originally contracted Hilli and also Gimi. You are right that for new FLNG projects, we will likely target structures that will allow us to have a significantly reduced equity contribution during the construction phase.

[Mike Webber, Webber Research]

Right. I guess what sticks out in my mind is Equatorial Guinea, all right, which would have been post Hilli, which had contracts, which wasn't able to see your financing. I know that was in part because of where it was being built, but you also had the complicating factor that the LNG market had turned and you're burning $100 million a year in that space. So, obviously that's not a concern right now, given where the market is and the outlook, but who knows where we are two to three years from now. So, I think that's trying to avoid a repeat cycle of what we've seen a couple times ago over the past decade is kind of the angle with which I'm asking.

[Karl Staubo, Chief Executive Officer]

Yes, no -- so, at the end of the day that resource is still there. It's still a very large resource. It's still got a very high quality gas. And it's natural to assume that we're evaluating that alongside any other integrated project. But as you say, we know what failed on that project last time around. So, if we're going back in, we need to ensure that that will not happen this time, but that's very far from the only integrated project we're looking at, so there's several currently under discussion right now.

[Mike Webber, Webber Research]

Right, okay. I can take that offline. Thanks for the time guys. Appreciate it.

[Karl Staubo, Chief Executive Officer]

Thank you.

[Operator]

[Operator Instructions] Our next question comes from the line of Sean Morgan from Evercore. Please go ahead with your question.

[Sean Morgan, Evercore ISI]

Hi, guys. Thanks for taking my questions. So, just to kind of follow up a little bit on some of what we've discussed on LNG, but as I look at the Slide on 11, I see we kind have a pretty widespread up to the 32 range for which I think sort of indicates spot activity in Asia for the integrated model. And so for that integrated model is there any need, you mentioned it would be a smaller one of the smaller builds for the FLNG. Is there any need to sort of backstop that -- that the cost to produce the asset with SPAa. And if you were to sign SPAs, is there -- are you seeing interest in the market for TTF and, and JKM based pricing based on the recent volatility we've seen in those kind of Asian and European spot prices or you think it's maybe a little bit more interest towards the Brent? If in fact you actually need to sign SPAs in order to finance the project.

[Karl Staubo, Chief Executive Officer]

Yes, sure. So, a natural model for the integrate that is that you try to create asymmetric risk profile, and in doing so it could be interesting to sell half of the volume or similar on SPA basis whether that's linked to TTF or JKM net back or whether it's linked to Brent depends on what you can negotiate with the end user. And then you said naked on the other half and be exposed to the market. But it could be interesting to fund parts of such projects with an SPA. And what -- at the end of the day, what search in SPA looks like depends on negotiations.

[Sean Morgan, Evercore ISI]

Okay. And so, in terms of lining up the financing with whether it's an export finance facility or more traditional bank facility, you think that there's a route that you could go where you you'd essentially doing an integrated project without having to rely on the SPA market at all.

[Karl Staubo, Chief Executive Officer]

It depends on whether you use an existing unit or a new unit. Like, I think it a bit of a premature question and it's a very directly into the business development of the company, but we would obviously not enter into an FLNG project without funding. So, funding is one of the key attributes when we build the project.

[Sean Morgan, Evercore ISI]

Okay. Thanks a lot.

[Karl Staubo, Chief Executive Officer]

Thanks.

[Operator]

And our next question comes from the line of Craig Shere from Tuohy Brothers. Please go ahead with your question.

[Craig Shere, Tuohy Brothers]

Good morning, our time. Congratulations on the good quarter. One question about the focus on the integrated approach, we've seen in recent months a break in the logjam that's been there for two to three years on long-term, large scale land based LNG contracting. And some new FIDs are certainly being teed up in the next couple quarters on top of the Qatari mid decade supply. As we think about the Perenco contract coming off in 2026 with Hilli, are you still as committed as ever to going this route on more commodity exposure even into mid and late decade?

[Karl Staubo, Chief Executive Officer]

Yes, I think if you go back to the Slide 19 that we showed in the deck here, LNG is expected to grow by 50% from 360 million tons to 550 million tons, and we need to see a significant ramp up in new liquifaction projects if we are to meet anywhere close to that development. So, the short answer is yes, we would be interested to take commodity exposure. But again, as the previous question, we would probably link that to fixed SPAs for at least half the volume to reduce any downside risk and have significant offsite exposure.

[Craig Shere, Tuohy Brothers]

Got you, okay…

[Karl Staubo, Chief Executive Officer]

Similar to what we have on Hilli really.

[Craig Shere, Tuohy Brothers]

Fair enough. And to what extend can you more for segue into more environmentally friendly clean tech? I mean, can your FLNG design support say 10% or 20% of the gas flow being spiked with hydrogen. Let's say you're in the Middle East project was very economic to have renewable electrolysis for green hydrogen. Can you support that with your technology?

[Karl Staubo, Chief Executive Officer]

I think what I'd say on that front is that we have a green team within Golar, which are currently exploring a number of ways of further optimizing our FLNG production, which includes looking into to those type of potential production enhancements, and also carbon capture solutions on some of the emissions. Again, there're so many different technologies flowing around these states. Most of them are at the concept stage, but very rapidly being developed. And we are trying to very closely monitor that will also engage with several of these companies as the technology gets more and more proven. So, we exactly which way that will take and what form I think engineers are better placed to answer than I am. But it's certainly something we're driving and have a very wrong focus on across the company, because we also see that that's a key attribute in getting new FLNG projects.

[Craig Shere, Tuohy Brothers]

Right. Okay, great. Thank you.

[Operator]

Our next question comes from the line of Omar Nokta from Clarksons Securities. Please go ahead with your question. Omar is your line on mute. Can you unmute yourself please?

Due to no response from the line of Omar, we are going to proceed to the following one. Our next question comes from the line of Liam Burke from B. Riley. Please go ahead with your question.

[Liam Burke, B. Riley]

Thank you. Karl, Eduardo, how are you?

[Karl Staubo, Chief Executive Officer]

Well, thanks. Hi, Liam.

[Eduardo Maranhao, Chief Financial Officer]

Hi, Liam.

[Liam Burke, B. Riley]

Karl, the returns on the commodity linked FLNGs are exceedingly high and attractive. Do you see any competitors coming into the market to try and compete away some of those opportunities for you?

[Karl Staubo, Chief Executive Officer]

I agree that they're very attractive. In terms of competitors that are trying -- there are several people looking at FLNG and there has been since we started it. I think for now, no one else has been able to prove the technology with the same operational track record. So, for now we feel like we have a very strong competitive advantage. But if these type of returns prevail, we would assume that other peoples will try to chime in as we go along, but for now we don't see any direct competitors.

[Liam Burke, B. Riley]

Okay. Thank you, Karl.

[Operator]

Next question comes from the line of Chris Wetherbee from Citi. Please go ahead with your question.

[James Yoon, Citi]

Hey, guys, James on for Chris. Just wanted to ask a quick question about the capital structure, obviously, you're interesting the converts in February, but just wanted to understand how you're thinking about it moving forward. Is there a target mix of unsecured? Is there more work to be done before we take on another project like essentially, where are you in sort of the process and sort of what does the end state look like as of now?

[Eduardo Maranhao, Chief Financial Officer]

Hi Chris, this is Eduardo here. Yes. So, as we explained on the presentation once we get all these refinances done and completed, we will be left with pretty much only the maturities of our vessels refinancing. So, there will be no material refinancing between now and the time of the Gimi is delivered. So, we believe that unless any new major project comes into the pipeline and we take a final investment decision within that timeframe.

We pretty much have all the refinancing under control and there will be no further need to explore any other such refinancings in the near-term. But having said and having listened to Karl presented all the business development opportunities that we explore right now upon a decision to move ahead with any of those projects, there will be the need to funds and to provide the necessary capital to explore a major, for example, FLNG opportunity. So, I think we continue to look, but the [indiscernible] until the Gimi is delivered, there will be no major maturities between now and then.

[James Yoon, Citi]

Got it. And just so I understand around the head, presumably lines approval to convert and under lines that just given where you're trading in sort of the outlook, just wanting to understand your strategy around hedging essentially, should we think of this as essentially a one-time thing or is it something that you might opportunistically do, if it makes sense? Just wanted to understand sort of your strategy around the hedge?

[Karl Staubo, Chief Executive Officer]

Sorry, was the question on the TTF hedge?

[James Yoon, Citi]

Correct.

[Karl Staubo, Chief Executive Officer]

And I think for us, we'll continue to do it opportunistically, if we see the indirect to be attractive.

[James Yoon, Citi]

Okay, so I'm sorry, just because little confusing it sounded like, I mean it sounds like you're looking at the valuation of fee and saying, I want to be a long-term holder, given that valuation, rather than in the release, it sounded like, hey, this is something we might need, might want to monetize, if we get another project to move forward with.

[Karl Staubo, Chief Executive Officer]

I can understand the interpretation of how you read the release, the purpose of it, because we've gotten a lot of questions on we have $540 million of cash invested into Gimi, that's part of our EV, but currently not generating cash flow because the unit isn't delivered. The same is true for our stake in new Fortress Energy and Avenir. Yes, NFE pays currently a small dividend, Avenir does more. So, the statement referred to the fact that you could take the Gimi stake and the cash invested or the cash value of the cash in NFV and Avenir. There could be a potential to redeploy that cash into FLNG project, which has a higher cash yield. That's how it was meant and absolutely not as a means of any near-term actions to be taken.

[James Yoon, Citi]

Perfect. That's a great clarification. Thanks, Karl.

[Karl Staubo, Chief Executive Officer]

Thanks.

[Operator]

We appear to have no further question. At this point, I'll hand the conference back to you sir.

[Karl Staubo, Chief Executive Officer]

That concludes Q3 presentation. Thank you all for dialing in and have a good day.

[Operator]

Ladies and gentlemen, thank you for your participation today. This concludes this conference. You may now disconnect your lines. Thank you.